The discharge into the atmosphere of sulfur compounds during processing and end-use of the petroleum products derived from sulfur-containing sour crude oil pose health and environmental problems. The stringent, reduced-sulfur specifications applicable to fuel products have impacted the refining industry, and made it necessary for refiners to take expensive and complex actions so as to reduce the sulfur content in gas oils to 10 parts per million by weight (ppmw) or less. In industrialized nations such as the United States, Japan and the countries of the European Union, refineries for transportation fuel are already required to produce environmentally clean products. For instance, in 2007 the United States Environmental Protection Agency began requiring the sulfur content of highway diesel fuel to be reduced 97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels sold in 2009 and thereafter to contain less than 10 ppmw of sulfur. Other countries are following in the footsteps of the United States and the European Union and are moving forward with regulations that will require refineries to produce transportation fuels with ultra-low sulfur levels.
To keep pace with recent trends toward production of ultra-low sulfur fuels, refiners must now choose from processes and/or crude oils that provide flexibility so that future specifications relating to lower sulfur levels may be met with minimum additional capital investment, while using existing equipment. Conventional technologies such as hydrocracking and two-stage hydrotreating offer alternative solutions for production of clean transportation fuels. These technologies are available and can be applied as new grassroots production facilities are constructed; however, many existing hydroprocessing facilities, such as those using relatively low pressure hydrotreaters, represent substantial prior investments and were constructed before these more stringent sulfur reduction requirements were enacted. It is very difficult to upgrade existing hydrotreating reactors in these facilities because of the comparatively more severe operational requirements (e.g., higher temperature and pressure) needed to produce so-called “clean” fuel. Available retrofitting options for refiners include elevation of the hydrogen partial pressure by increasing the recycled gas quality, utilization of more active catalyst compositions, installation of improved reactor components to enhance liquid-solid contact, increase of reactor volume, and improvement of feedstock quality.
There are many hydrotreating units installed worldwide, which produce transportation fuels containing 500-3000 ppmw sulfur. These units were designed for, and are being operated at, relatively mild conditions (e.g., low hydrogen partial pressures of 30 kilograms per square centimeter for straight run gas oils with boiling points in the range of 180° C.-370° C.
The increasing prevalence of more stringent environmental sulfur specifications with the maximum allowable sulfur levels reduced to no greater than 15 ppmw, and in some cases no greater than 10 ppmw, present difficult challenges. This ultra-low level of sulfur in the end product typically requires either construction of new high pressure hydrotreating units, or a substantial retrofitting of existing facilities, e.g., by integrating new reactors, incorporating gas purification systems, reengineering internal configurations and components of reactors, and/or deployment of more active catalyst compositions.
Sulfur-containing compounds that are typically present in hydrocarbon fuels include aliphatic molecules such as sulfides, disulfides and mercaptans, as well as aromatic molecules such as thiophene, benzothiophene and its long chain alkylated derivatives, dibenzothiophene, and its alkyl derivatives such as 4,6-dimethyldibenzothiophene. Aromatic sulfur-containing molecules have a higher boiling point than aliphatic sulfur-containing molecules, and are consequently more abundant in higher boiling fractions.
In addition, certain fractions of gas oils possess different properties. The following table illustrates the properties of light and heavy gas oils derived from Arabian Light crude oil:
TABLE 1Feedstock NameLightHeavyBlending Ratio——API Gravity°37.530.5CarbonW %85.9985.89HydrogenW %13.0712.62SulfurW %0.951.65Nitrogenppmw42225ASTM D86 DistillationIBP/5 V %° C.189/228147/24410/30 V %° C.232/258276/32150/70 V %° C.276/296349/37385/90 V %° C.319/330392/39895 V %° C.347Sulfur SpeciationSulfur Compounds Boilingppmw45913923Less than 310° C.Dibenzothiophenesppmw10412256C1-Dibenzothiophenesppmw14412239C2-Dibenzothiophenesppmw13252712C3-Dibenzothiophenesppmw11045370
As set forth above in Table 1, the light and heavy gas oil fractions have ASTM D85 95 V % points of 319° C. and 392° C., respectively. Further, the light gas oil fraction contains less sulfur and nitrogen than the heavy gas oil fraction (0.95 W % sulfur as compared to 1.65 W % sulfur and 42 ppmw nitrogen as compared to 225 ppmw nitrogen).
Advanced analytical techniques such as multi-dimensional gas chromatography (Hua R., et al., Journal of Chromatog. A, 1019 (2003) 101-109), have shown that the middle distillate cut boiling in the range of 170-400° C. contains sulfur species including thiols, sulfides, disulfides, thiophenes, benzothiophenes, dibenzothiophenes, and benzonaphthothiophenes, with and without alkyl substituents.
The sulfur specification and content of light and heavy gas oils are conventionally analyzed by two methods. In the first method, sulfur species are categorized based on structural groups. The structural groups include one group having sulfur-containing compounds boiling at less than 310° C., including dibenzothiophenes and their alkylated isomers, and another group including 1, 2, and 3 methyl-substituted dibenzothiophenes, denoted as C1, C2 and C3, respectively. Based on this method, the heavy gas oil fraction contains more alkylated di-benzothiophene molecules than the light gas oils.
In the second method of analysis, the sulfur content of light and heavy gas oils are plotted against the boiling points of the sulfur-containing compounds to observe concentration variations and trends. See, e.g., FIG. 1 of Koseoglu, et al., Saudi Aramco Journal of Technology, 66-79 (Summer 2008), incorporated by reference. Note that the boiling points depicted are those of sulfur-containing compounds that were detected rather than the boiling point of the total hydrocarbon mixture. The boiling point of the key sulfur-containing compounds consisting of dibenzothiophenes, 4-methydibenzothiophenes and 4,6-dimethyldibenzothiophenes are also shown in FIG. 1. The cumulative sulfur specification curves show that the heavy gas oil fraction contains a higher content of heavier sulfur-containing compounds and lower content of lighter sulfur-containing compounds as compared to the light gas oil fraction. For example, it is found that 5370 ppmw of C3-dibenzothiophene, and bulkier molecules such as benzonaphthothiophenes, are present in the heavy gas oil fraction, compared to 1104 ppmw in the light gas oil fraction. In contrast, the light gas oil fraction contains a higher content of light sulfur-containing compounds compared to heavy gas oil. Light sulfur-containing compounds are structurally less bulky than dibenzothiophenes and boil at less than 310° C. Also, twice as much C1 and C2 alkyl-substituted dibenzothiophenes exist in the heavy gas oil fraction as compared to the light gas oil fraction.
Aliphatic sulfur-containing compounds are more easily desulfurized (labile) using conventional hydrodesulphurization methods. However, certain highly branched aliphatic molecules can hinder the sulfur atom removal and are moderately more difficult to desulfurize (refractory) using conventional hydrodesulphurization methods.
Among the sulfur-containing aromatic compounds, thiophenes and benzothiophenes are relatively easy to hydrodesulfurize. The addition of alkyl groups to the ring compounds increases the difficulty of hydrodesulphurization. Dibenzothiophenes resulting from addition of another ring to the benzothiophene family are even more difficult to desulfurize, and the difficulty varies greatly according to their alkyl substitution, with di-beta substituted compounds being the most difficult to desulfurize, thus justifying their “refractory” appellation. These beta substituents hinder exposure of the heteroatom to the active site on the catalyst.
The economical removal of refractory sulfur-containing compounds is therefore exceedingly difficult to achieve, and accordingly removal of sulfur-containing compounds in hydrocarbon fuels to an ultra-low sulfur level using current hydrotreating techniques is very costly. When previous regulations permitted sulfur levels up to 500 ppmw, there was little need or incentive to desulfurize beyond the capabilities of conventional hydrodesulphurization processes and hence the refractory sulfur-containing compounds were not targeted; however, in order to meet the more stringent sulfur specifications, these refractory sulfur-containing compounds must be substantially removed from hydrocarbon fuels streams.
Relative reactivities of sulfur-containing compounds based on their first order reaction rates at 250° C. and 300° C. and 40.7 Kg/cm2 hydrogen partial pressure over Ni—Mo alumina catalyst, and activation energies, are given in Table 2 (Steher et al., Fuel Processing Technology, 79:1-12 (2002)):
TABLE 24-methyl-dibenzo-4,6-dimethyl-dibenzo-NameDibenzothiophenethiophenethiopheneFormula k@250, s−157.710.41.0k@300, s−17.32.51.0Ea,28.736.153.0Kcal/mol
As is apparent from Table 2, dibenzothiophene is 57 times more reactive than the refractory 4,6-dimethyldibenzothiphene at 250° C. The relative reactivity decreases with increasing operating severity. With a 50° C. temperature increase, the relative reactivity of di-benzothiophene compared to 4,6-dibenzothiophene decreases to 7.3 from 57.7.
The development of non-catalytic processes for desulphurization of petroleum distillate feedstocks has been widely studied, and certain conventional approaches are based on oxidation of sulfur-containing compounds are described, e.g., in U.S. Pat. Nos. 5,910,440; 5,824,207; 5,753,102; 3,341,448 and 2,749,284.
Oxidative desulphurization as applied to middle distillates is attractive for several reasons. First, mild reaction conditions, e.g., temperatures ranging from room temperature up to 200° C. and pressures ranging from 1 up to 15 atmospheres, are normally used, thereby resulting a priori in reasonable investment and operational costs, especially for hydrogen consumption, which is usually expensive. Another attractive aspect is related to the reactivity of high aromatic sulfur-containing species. This is evident since the high electron density at the sulfur atom caused by the attached, electron-rich aromatic rings, further increased by the presence of additional alkyl groups on the aromatic rings, will favor its electrophilic attack as shown in Table 3 (Otsuki, et al., Energy Fuels, 14:1232 (2000)). However, the intrinsic reactivity of molecules such as 4,6-DMDBT should be substantially higher than that of DBT, which is much easier to desulfurize by hydrodesulfurization.
TABLE 3Electron density of selected sulfur speciesSulfur compoundFormulasElectron DensityK (L/(mol · min))Thiophenol5.9020.270 Methyl Phenyl Sulfide5.9150.295 Diphenyl Sulfide5.8600.156 4,6-DMDBT5.7600.0767 4-MDBT5.7590.0627 Dibenzothiophene5.7580.0460 Benzothiophene5.7390.00574 2,5-Dimethylthiophene5.716— 2-methylthiophene5.706— Thiophene5.696—
Certain existing desulfurization processes incorporate both hydrodesulfurization and oxidative desulfurization. For instance, Cabrera et al., U.S. Pat. No. 6,171,478 describes an integrated process in which the hydrocarbon feedstock is first contacted with a hydrodesulfurization catalyst in a hydrodesulfurization reaction zone to reduce the content of certain sulfur-containing molecules. The resulting hydrocarbon stream is then sent in its entirety to an oxidation zone containing an oxidizing agent where residual sulfur-containing compounds are converted into oxidized sulfur-containing compounds. After decomposing the residual oxidizing agent, the oxidized sulfur-containing compounds are solvent extracted, resulting in a stream of oxidized sulfur-containing compounds and a reduced-sulfur hydrocarbon oil stream. A final step of adsorption is carried out on the latter stream to further reduce the sulfur level.
Kocal, U.S. Pat. No. 6,277,271 also discloses a desulfurization process integrating hydrodesulfurization and oxidative desulfurization. A stream composed of sulfur containing hydrocarbons and a recycle stream containing oxidized sulfur-containing compounds is introduced in a hydrodesulfurization reaction zone and contacted with a hydrodesulfurization catalyst. The resulting hydrocarbon stream containing a reduced sulfur level is contacted in its entirety with an oxidizing agent in an oxidation reaction zone to convert the residual sulfur-containing compounds into oxidized sulfur-containing compounds. The oxidized sulfur-containing compounds are removed in one stream and a second stream of hydrocarbons having a reduced concentration of oxidized sulfur containing compounds is recovered. Like the process in Cabrera et al., the entire hydrodesulfurized effluent is subjected to oxidation in the Kocal process.
Wittenbrink et al., U.S. Pat. No. 6,087,544 discloses a desulfurization process in which a distillate feedstream is first fractionated into a light fraction containing from about 50 to 100 ppm of sulfur, and a heavy fraction. The light fraction is passed to a hydrodesulfurization reaction zone. Part of the desulfurized light fraction is then blended with half of the heavy fraction to produce a low sulfur distillate fuel. However, not all of the distillate feedstream is recovered to obtain the low sulfur distillate fuel product, resulting in a substantial loss of high quality product yield.
Rappas et al., PCT Publication No. WO 02118518 discloses a two-stage desulfurization process located downstream of a hydrotreater. After having been hydrotreated in a hydrodesulfurization reaction zone, the entire distillate feedstream is introduced to an oxidation reaction zone to undergo biphasic oxidation in an aqueous solution of formic acid and hydrogen peroxide. Thiophenic sulfur-containing compounds are converted to corresponding sulfones. Some of the sulfones are retained in the aqueous solution during the oxidation reaction, and must be removed by a subsequent phase separation step. The oil phase containing the remaining sulfones is subjected to a liquid-liquid extraction step. In the process of WO 02118518, like Cabrera et al. and Kocal, the entire hydrodesulfurized effluent is subject to oxidation reactions, in this case biphasic oxidation.
Levy et al., PCT Publication No. WO 031014266 discloses a desulfurization process in which a hydrocarbon stream having sulfur-containing compounds is first introduced to an oxidation reaction zone. Sulfur-containing compounds are oxidized into the corresponding sulfones using an aqueous oxidizing agent. After separating the aqueous oxidizing agent from the hydrocarbon phase, the resulting hydrocarbon stream is passed to a hydrodesulfurization step. In the process of WO 031014266, the entire effluent of the oxidation reaction zone is subject to hydrodesulfurization.
Gong et al., U.S. Pat. No. 6,827,845 discloses a three-step process for removal of sulfur- and nitrogen-containing compounds in a hydrocarbon feedstock. All or a portion of the feedstock is a product of a hydrotreating process. In the first step, the feed is introduced to an oxidation reaction zone containing peracid that is free of catalytically active metals. Next, the oxidized hydrocarbons are separated from the acetic acid phase containing oxidized sulfur and nitrogen compounds. In this reference, a portion of the stream is subject to oxidation. The highest cut point identified is 316° C. In addition, this reference explicitly avoids catalytically active metals in the oxidation zone, which necessitates an increased quantity of peracid and more severe operating conditions. For instance, the H202:S molar ratio in one of the examples is 640, which is extremely high as compared to oxidative desulfurization with a catalytic system.
Gong et al., U.S. Pat. No. 7,252,756 discloses a process for reducing the amount of sulfur- and/or nitrogen-containing compounds for refinery blending of transportation fuels. A hydrocarbon feedstock is contacted with an immiscible phase containing hydrogen peroxide and acetic acid in an oxidation zone. After a gravity phase separation, the oxidized impurities are extracted with aqueous acetic acid. A hydrocarbon stream having reduced impurities is recovered, and the acetic acid phase effluents from the oxidation and the extraction zones are passed to a common separation zone for recovery of the acetic acid. In an optional embodiment, the feedstock to the oxidation process can be a low-boiling component of a hydrotreated distillate. This reference contemplates subjecting the low boiling fraction to the oxidation zone.
M. A. Ledile, et al., Tetrahedron Lett., 10:785 (1976) reported the use of RuOx for oxidation of DBT at 100° C. under 70 bar of air. Sulfur conversion of 97% was obtained after 12 hours.
Recently, the use of cobalt and manganese based catalysts in air based oxidation of DBT type aromatic sulfur compounds into polar sulfones and/or sulfoxides has been described. See, e.g., PCT Application No. WO 2005/116169. A wide number of transition metal oxides, including MnO2, Cr2O3, V2O5, NiO, MoO3 and Co3O4, or transition metal containing compounds such as chromates, vanadates, manganates, rhenates, molybdates and niobates are described, but the more active and selective compounds were manganese and cobalt oxides. It was shown that the manganese or cobalt oxides containing catalysts provided 80% oxidation conversion of DBT at 120° C. One advantage these catalysts is that the treatment of fuel takes place in the liquid phase. The general reaction scheme for the ODS process suggested is as follows: sulfur compound R—S—R′ is oxidized to sulfone R—SO2—R′, and the latter can decompose with heating, to liberate SO2 and R—R′, while leaving behind a useful hydrocarbon compounds that can be utilized. A recommended temperature is from 90° C. to 250° C.
High catalytic activity of manganese and cobalt oxides supported on Al2O3 in oxidation of sulfur compounds at 130-200° C. and atmospheric pressure has been described by Sampanthar J. T., et al., Appl. Catal. B: Environm., 63(1-2):85-93 (2006). The authors show that, after the subsequent extraction of the oxidation products with a polar solvent, the sulfur content in the fuel decreased to 40-60 ppmw. The thiophenes conversion increased with time and it reached its maximum conversion of 80-90% in 8 h. It was shown that the trisubstituted dibenzothiophene compounds were easier to be oxidized than the monosubstituted dibenzothiophenes. The oxidative reactivity of S-compounds in diesel follows the order: trialkylsubstituted dibenzothiophene > dialkyl-substituted dibenzothiophene > monoalkyl-substituted dibenzothiophene > dibenzothiophene. These results showed that the most refractory sulfur compounds in the diesel hydrodesulfurization were more reactive in the oxidative desulfurization of fuel.
U.S. Pat. No. 5,969,191 describes a catalytic thermochemical process employing a catalyst whose texture is chosen so as to avoid deep oxidation reacting. A key catalytic reaction step in the thermochemical process scheme is the selective catalytic oxidation of organosulfur compounds (e.g., mercaptan) to a valuable chemical intermediate (e.g., CH3SH+2O2→H2CO+SO2+H2O) over certain supported (mono-layered) metal oxide catalysts. The preferred catalyst employed in this process consists of a specially engineered V2O5/TiO2 catalyst that minimizes the adverse effects of heat and mass transfer limitations that can result in the over oxidation of the desired H2CO to COx and H2O.
The process described later by the inventors in PCT Application No. WO 2003/051798 (A1) involves contacting of heterocyclic sulfur compounds in a hydrocarbon stream, e.g., in a petroleum feedstock or petroleum product, in the gas phase in the presence of oxygen with a supported metal oxide catalyst, or with a bulk metal oxide catalyst to convert at least a portion of the heterocyclic sulfur compounds to sulfur dioxide and to useful oxygenated products as well as sulfur-deficient hydrocarbons and separately recovering the oxygenated products separately from a hydrocarbon stream with substantially reduced sulfur. The catalytic metal oxide layer supported by the metal oxide support is based on a metal selected from the group consisting of Ti, Zr, Mo, Re, V, Cr, W, Mn, Nb, Ta, and mixtures thereof. Generally, a support of titania, zirconia, ceria, niobia, tin oxide or a mixture of two or more of these is preferred. Bulk metal oxide catalysts based on molybdenum, chromium and vanadium can be also used. Sulfur content in fuel could be less than about 30-100 ppmw. The optimum space velocity likely will be maintained below 4800 V/V/hr and the temperature will be 50-200° C.
The vapor-phase oxidative desulfurization of various sulfur compounds (such as: COS, or CS2, CH3SH, CH3SCH3, CH3SSCH3, thiophene and 2,5-dimethylthiophene) by use of sulfur-tolerant V2O5-containing catalysts on different supports has been taught by Choi, S.; et al., Preprints of Symposia—American Chemical Society, Division of Fuel Chemistry, 47(1):138-139 (2002) 138-139 and Choi S., et al., Preprints of Symposia—American Chemical Society, Division of Fuel Chemistry, 49(2):514-515 (2004). In these papers, the feed gas contained 1000 ppmw of COS, or CS2, CH3SH, CH3SCH3, CH3SSCH3, thiophene and 2,5-dimethylthiophene, 18% O2 in He balance. The formed products (formalin, CO, H2, maleic anhydride and SO2) were monitored by temperature programmed surface reaction mass spectrometry. It was shown that the turnover frequency for COS and CS2 oxidation varied by about one order of magnitude depending on the support, in the order CeO2>ZrO2>TiO2>Nb2O5>Al2O3—SiO2.
A common catalyst for oxidative desulfurization is activated carbon (Yu et al., Energy & Fuels, 19(2):447-452 (2005), Wu et al., Energy and Fuels, 19(5):1774-1782 (2005)). The application of this method allows removal of hydrogen sulfide from gaseous fuels at 150° C. by oxidation with air (Wu et al., Energy and Fuels, 19(5):1774-1782 (2005) and also sulfur removal from diesel fuels using hydrogen peroxide (Yu et al., Energy & Fuels, 19(2):447-452 (2005)). The higher adsorption capacity of the carbon, the higher its activity in the oxidation of dibenzothiophene.
The prior art evidences different ways to approach the problem of desulfurizing fuels.
U.S. Pat. No. 7,749,376 to Turbeville, et al., describes catalytic processes whereby sulfur-containing compounds are adsorbed onto a catalytic bed. The process is carried out with liquid hydrocarbons, at low temperatures. It is a non-oxidative process, which uses a catalyst with a hydrotalcite structure of the form (Cu,Zn)6Al2(OH)16CO3*4H2O2.
U.S. Pat. No. 4,596,782 to Courty, et al., teaches a catalytic process for producing ethanol and methanol over a Cu—Zn—Al catalyst. The catalyst requires activation via, e.g., reducing conditions and a substance such as H2, CO, or an alcohol, resulting in the reduction of copper oxide to metal copper particles, which are active in the well known Fischer-Tropsch process.
U.S. Pat. No. 3,945,914 to Yoo, et al., describes a catalytic process for removing sulfur compounds from liquid hydrocarbons. The catalyst employed differs markedly from the invention described herein.
U.S. Pat. No. 2,640,010 to Hoover, et al., describes a process for removing sulfur-containing compounds from gaseous phase hydrocarbons; however, the catalyst is markedly different from the present invention.
None of these references teach or suggest the catalytic composition of the invention, its use in removal of sulfur containing compounds from gaseous phase hydrocarbons in either an oxidative process or an adsorptive process, or the processes by which these catalysts are made.
Therefore, a need exists for an efficient and effective process and apparatus for desulfurization of hydrocarbon fuels to an ultra-low sulfur level.
Accordingly, it is an object of the present invention to desulfurize a hydrocarbon fuel stream containing different classes of sulfur-containing compounds having different reactivities, utilizing reactions separately directed to labile and refractory classes of sulfur-containing compounds.
It is a further object of the present invention to produce hydrocarbon fuels having an ultra-low sulfur level by gas phase oxidative and/or adsorptive desulphurization of refractory organosulfur compounds.
As used herein in relation to the apparatus and process of the present invention, the term “labile organosulfur compounds” means organosulfur compounds that can be easily desulfurized under relatively mild hydrodesulfurization pressure and temperature conditions, and the term “refractory organosulfur compounds” means organosulfur compounds that are relatively more difficult to desulfurize under mild hydrodesulfurization conditions.
The desulphurization of the hydrocarbon full stream may occur via one of two reaction routes. In a first route, the so-called “oxidative process,” the sulfur compounds are oxidized, wherein at least a portion of them are oxidized to SO2. In a second route, the so-called “adsorptive process,” the compounds are converted to one or more of sulfates, sulfites, and sulfides. Which route is chosen depends upon reaction conditions as well as the type and amount of sulfur compounds in the hydrocarbon fuel stream. When the adsorptive route is used, it is necessary to regenerate the catalysts at some point, so as to remove the sulfur compounds adsorbed therein.
How the various aspects of the invention are achieved will be seen in the detailed description which follows.